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Home My WebLink About2006 Alpine Oil PoolConocoPhillips Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Chris Wilson Supervisor, WNS Base Phone (907) 265-6822 Fax: (907) 265-1515 March 28, 2007 Alaska Oil and Gas Conservation Commission Attention: Mr. John Norman 333 West 7th Ave, Suite 100 Anchorage, AK 99501 MAR 3 0 2001 Alaska Oil & Gas Cons. Commission Anchorage Subject: Annual Surveillance Report for the Alpine Oil Pool of the Colville River Unit Commissioner Norman: ConocoPhillips Alaska, Inc., as Operator and on behalf of the working interest owners of the Colville River Unit submits this, the Annual Surveillance Report for the Alpine Oil Pool of the Colville River Unit. This report is submitted in compliance with Rule 8, of Conservation Order No. 443, and reflects the status of the Alpine Pool of the Colville River Unit as of March 1, 2007. If you have any questions or require additional information, please contact me at ConocoPhillips Alaska, Inc., P. O. Box 100360, Anchorage, Alaska, 99510-0360, Telephone: (907) 263-6822. Attachment 1 illustrates the current unit boundary, which was revised in August of 2005. 1.0 Progress of Recovery Projects 1.1 Average Metrics for 2006 - Average oil production rate 114.3 MBOPD - Average gas production rate 138.6 MMSCFD - Average water production rate 13.2 MBWPD - Average gas injection rate 126.5 MMSCFD - Average water injection rate 128.9 MBWPD 1.2 Cumulative Volumes Produced and Injected Through January 2007 - Cumulative oil production through January 2007: 229,625,849 STBO - Cumulative gas production through January 2007: 265,171.370 MSCF - Cumulative water production through January 2007: 8,596,602 STBW - Cumulative gas injection through January 2007: 233,770,721 MSCF - Cumulative water injection through January 2007: 228,810,910 STB 1.3 Miscible Water Alternating Gas Flood Management During 2006 Development of the Alpine reservoir is based on a Miscible Water Alternating Gas (MWAG) project design. Alpine EOR facilities have been described in previous testimony before the AOGCC. This discussion will provide a narrative update on key reservoir management issues for the time period of January 2006 through January 2007. CQ1 Attachment 3 gives an overview of the miscible water -alternating -gas (MWAG) conversion status at CD1 in a tabular form. The MWAG flood has now significantly matured at GD1, as shown in Attachment 4. GD1 averages an HC;PV throughput of approximately 72% amongst the 22 MWAG injectors there. Five wells have completed the target MI slug of approximately 30% HCPV (CD1-03, CD1-05, CD1-21, CD1-23, & CD1-39). Seventeen wells have completed or are on their 2nd cycle of MI, after having been temporarily converted to seawater injection in order to alleviate rising GOR trends in offset producers. Eight wells have completed or are on their 3rd cycle of MI. Five wells, CD1-01, CD1-02, CD1-03, CD1-13, and CD1-31 have completed or are on their 4th cycle of MI. No wells have begun a 5th cycle of MI at this time. Seventeen MWAG injectors have completed or are on their 2nd cycle of seawater injection. Fifteen wells have completed or are on their 3d cycle of seawater injection and five wells, CD1-01, CD1-02, CD1-03, CD1-13, and CD1-21, have completed or are on their 4th cycle of seawater injection. One well, CD1-03, is on its 5th cycle of seawater injection. The main drivers behind the rate of maturation of the different patterns are field offtake, local re -pressurization schemes to allow for efficient development drilling, local voidage balance requirements, seawater availability, MI enrichment requirements and the necessity to control GOR within compressor limits. CD2 Attachment 5 gives an overview of the MWAG conversion status in a tabular form. Attachment 6 shows the maturity of the different injection centered patterns at CD2. CD2 is significantly less mature than CD1, with only 31% overall throughput. This is due to a combination of factors: Production started up later than at CD1, and the offtake and throughput rates at CD2 were lower due to ongoing development drilling. Also, larger reserves are present at CD2, and the lower rock quality will not allow the same production rates as seen at CD1. Thirty-one MWAG injectors are in place at CD2. Ten injectors are on their first cycle of seawater injection. Twenty-five wells have completed or are on their first cycle of MI injection. Thirteen wells have completed or are on their 2nd cycle of MI injection. Twenty wells have completed or are on their 2nd cycle of seawater injection. Nine wells are currently on their 3d cycle of seawater injection and PA three wells (CD2 -07, CD2 -29, and CD2 -44) are on their 3rd cycle of MI. Of the 31 MWAG injectors at CD2, six have not started their 1St MI slug (CD2 -30, CD2 -40, CD2 - 55, CD2 -56, CD2 -59, and CD2 -60). Six wells (CD2 -02, CD2 -11, CD2 -18, CD2 -54, CD2 -56, and CD2 -59) have been completed in the Alpine A sand. These wells are on or have completed their 1St cycle of MI injection with the exception of CD2 -56 and CD2 -59. No problems with injectivity have been observed while on water or gas and a good response by offset producers completed in the A sand suggest that this sand should deliver similar recovery factors as seen in the C sand. Overall field response to the MWAG remains excellent. Attachment 7 shows the recovery -throughput relation from all active MWAG patterns, and attests to the effectiveness of the EOR flood at Alpine. 1.4 MI Enrichment Challenges The MI stream consists of lean gas from the field gas production stream (blend gas) and C2+ enriching components extracted from either the condensate flash drum (when stabilizer offline) or the stabilizer reflux drum when in stabilizer operation. Enriching components can also be produced by the Joule Thompson Unit while in MI service. With the commissioning of the Gas Condensate Stabilizer Unit in December 2006, the MI enrichment process has taken on another level of complexity. The stabilizer can as the name implies stabilize C5+ components for injection into the sales crude stream leaving the plant. This process can reduce the amount of blending fluid available for MI enrichment thus affecting the overall volume of MI produced at any given MMP spec. A team has been put together to study the cause and affect relationship between gas production, blending fluid availability, stabilizer operation, MI generation, and long term EOR performance to shed light on the optimum system configuration. Part of the field management strategy focuses on maintaining the MMP of the injected MI lower than the average reservoir pressure. This requires a certain enrichment level of the MI stream that cannot always be achieved by using all the blend gas. Some of the blend gas must therefore be injected into an up -structure lean gas well to ensure adequate composition of the MI stream. For optimal EOR performance, the amount of lean gas injection is kept to a minimum. The composition of the injected miscible gas is routinely monitored and adjusted with the miscible gas/lean gas split to ensure miscibility with the reservoir oil. 1.5 Reservoir Management for 2007 In the second half of 2006, Alpine began sharing the production and injection facilities with Fiord and Nanuq. During this time period back -out due to facility handling limits was minimal, however, to the extent that the shared production facilities reach handling limits, rates from the least efficient producers, in any of the developments, may have to be limited. However, this will maximize the overall oil production rate from the combined developments. In 2007 reservoir management of the main Alpine field will concentrate on maximizing oil production rate by targeting a pattern I/W of 1, injection capacity permitting. To the extent that producing GORs can be reduced, oil rate will be maximized, especially in the summer months when gas compression capacity is reduced by warmer ambient temperatures. In addition, productivity will be increased by hydraulically fracturing up to 6 producers. However, now that Alpine development drilling is complete, its production rate is expected to decline throughout 2007. The satellite fields were anticipated to need up to 20,000 BWPD of injection water in 2006, however better than expected performance from the Nanuq-Kuparuk reservoir bumped this demand up to 33,000 BWPD by year-end 2006. Satellite demand will continue to increase in 2007 to approximately 50,000 BWPD. Alpine water production is expected to rise during the year, bringing the volume of water available for injection (produced water plus imported water from GKA) close to the available water injection capacity (150,000 BWPD). Diversion of some of this injection water to the satellites may result in less water injection than required for full voidage replacement in the Alpine reservoir. In that case, Alpine production may be temporarily prorated to maintain complete voidage replacement. The 2006 Alpine Reservoir Management Plan anticipated drilling 2 wells from CD4. Drilling results from the first well, CD4 -17 (injector), suggested that drilling the second well, CD4 -16 (producer), might not access as much un -swept oil as previously predicted. Testing of CD4 -17 has begun with the goal of better defining the productive potential of this injector -producer pattern. Should the CD4 -17 tests demonstrate that CD4 -16 will be an economic producer, then the well will be drilled in 2007 (subject to drilling rig availability). Additional Alpine wells drilled from CD4 are currently being evaluated for the 2007-08 drilling seasons. 2.0 Alpine Production and Injection by Month 11 Total Month Oil Gas Water Wtr Inj Gas Inj MI Inj Gas Inj MSTBO MMSCF STBW MSTBW MMSCF MMSCF MMSCF 2/28/2006 3,526.1 4,026.5 316.0 4,043.2 103.1 3,446.7 3,549.9 3/31/2006 3,918.3 4,797.1 364.5 4,526.6 152.7 4,104.9 4,257.6 4/30/2006 3,765.9 4,662.5 378.5 4,401.2 137.0 4,015.7 4,152.7 5/31/2006 3,827.7 4,921.2 447.1 3,763.7 189.6 4,220.2 4,409.8 6/30/2006 3,457.8 4,581.5 322.0 4,151.9 403.0 3,710.2 4,113.2 7/31/2006 2,996.3 3,977.9 387.2 2,596.7 382.7 3,169.3 3,552.0 8/31/2006 3,582.9 4,277.0 421.1 4,480.2 417.2 3,598.0 4,015.1 9/30/2006 3,242.7 3,806.2 365.0 4,149.2 375.6 3,193.8 3,569.4 10/31/2006 3,408.0 3,910.9 492.6 2,983.8 398.7 3,223.8 3,622.5 11/30/2006 2,781.6 3,239.5 451.2 4,052.0 334.0 2,634.6 2,968.6 12/31/2006 3,256.8 3,824.8 500.4 3,554.2 359.0 3,553.2 3,912.2 1/31/2007 3,217.8 3,648.7 501.3 3,345.9 455.0 3,157.5 3,612.5 11 3.0 Survey Results 3.1 Reservoir Pressure Monitoring Several pressure surveys were conducted on Alpine wells during the course of operations in 2006. The reservoir is continuously being managed to allow for local pressure build up in areas of historic under injection whilst maintaining average pattern pressures at or above the level required for stable production and optimum EOR performance in the rest of the field. Reservoir pressures are estimated from the Alpine full field simulation model as well as from inflow performance relation analysis on all drilled producers. Both approaches are calibrated with actual reservoir pressure measurements collected from static surveys taken in development wells. The Annual Reservoir Pressure Report for Alpine was issued to the AOGCC on January 17, 2007, and contains all reservoir pressure data gathered during the course of 2006. 3.2 Well Surveillance Nine Alpine wells had reservoir pressure measured via static pressure surveys in 2006. Per Alpine's scale management program quarterly samples from wells producing greater than or equal to five percent water cut or fifty BWPD were acquired to determine scaling potentials. Based on the sampling results six wells had slight to moderate scaling potential therefore, gauge ring runs were performed to verify that no scale build up existed in the tubular. Six fracture stimulations were performed in 2006 that resulted in appreciable production rate increases. Based on the fracturing success at Alpine additional stimulations are planned for 2007. 4.0 Field Development 4.1 Development Wells Drilled as of March 31, 2007 104 wells drilled total: o 21 CD1 producers o 22 CD1 injectors o 27 CD2 producers o 31 CD2 injectors o 1 CD4 injector o 2 Disposal wells 4.2 Development Drilling Completed in 2006 All Alpine wells planned for development of the main field from CD1 and CD2 have been drilled and completed as of November 2005. In 2006, CD4 -17 was drilled from CD4 as part of a planned 2 -well development of a single injector/producer pattern in the southwest corner of the PA. The Alpine reservoir drilled by CD4 -17 proved to have much higher water saturation than anticipated. 5 This drilling result called into question the viability of drilling the offset producer, CD4 - 16, unless it could be demonstrated that the water found by CD4 -17 was a small reservoir volume swept by water from CD2 -56. After the rig moved off CD4 -17, a testing program was developed to determine the risk of finding sufficient recoverable oil in CD4 -16's drainage area to justify drilling that well. Initial results from the testing program support a high probability of finding sufficient oil, but more definitive testing is currently underway. The test results are expected to be reviewed by the end of 1Q07, after which the Operator will issue a recommendation whether to drill CD4 -16. If a decision is made to drill this well it will be scheduled to fit in between Fiord and Nanuq drilling requirements. We are currently reprocessing the CRU 3D seismic survey to enhance frequency and resolution. The goal will be to identify potential Alpine drilling opportunities at CD1. Depending upon the outcome of the 2007 CD4 drilling results, prospects at CD1 may be available to substitute for the remaining drilling season. 4.3 Fracture Stimulations in 2006 Six fracture stimulations were performed in 2006 on CD1-40, CD1-41, CD2 -43, CD2 -47, CD2 -53, and CD2 -58 that resulted in appreciable production rate increases and reserve adds. Based on these results, plans are to stimulate additional wells in 2007. 4.4 Development Drilling in 2007 All Alpine wells planned for development of the main field have been drilled and completed as of November 2005. Depending upon results from the flow back of well CD4 -17 a decision will be made to proceed or other wise with well CD4 -16. Further study may identify other opportunities to drill new wells on the periphery of the field, or extend existing wells. If these opportunities are considered attractive they may be added to the 2007 drilling program. 4.5 Facilities Expansion Evaluation Results and Update Prior to the summer of 2004, the combined well productivity from CD1 and CD2 regularly exceeded the plant's capacity. Various wells were choked from time to time to manage the oil production rate. Major facility expansion was required to increase the oil rate. Concurrent with expansion of the oil train, expansion of the seawater injection system was needed to support higher offtake rates. ACX Phase 1 The Alpine Capacity Expansion Project Phase 1 (ACX1) was approved by the Alpine working interest owners in April 2003, and work was completed in the summer of 2004. The ACX1 Project increased oil production rates by 5,000 BOPD (gross). The project increased oil and gas processing capacity, and enabled re-injection of produced water into the Alpine formation. ACX1 increased the produced water handling system from 10 MBWPD to 100 MBWPD, and gas processing capacity from 130 MMSCFD to 160 MMSCFD. All ACX Phase 2 The Alpine Capacity Expansion Project Phase 2 (ACX2) was approved by the Alpine working interest owners in February 2004., and work was completed in the 2004 and 2005 summer shut down periods. Building on ACX1, the ACX2 project consisted of adding or upgrading equipment to increase the oil processing capacity to 140 MBOPD rate (at watercuts less than 1 %), added another 20 MMCFD of gas processing capacity (to 180 MMSCFD total), and expanded the seawater injection capacity to 133 MBWPD (from 98 MBWPD). The ACX2 project enhances the Alpine recovery process. The seawater injection system allows higher throughput rates and increases cumulative water injection which results in increased incremental recovery. ACX2 expansion of the gas handling system increases the volume of miscible injectant available for the MWAG flood which results in a larger cumulative volume of miscible injectant in the reservoir and therefore incrementally higher EOR recovery from the MWAG process. ACX Phase 3 In January 2005 the Alpine working interest owners approved the Alpine Capacity Expansion Project Phase 3 (ACX3). The ACX3 project installed a stabilizer column, fired heater, reflux drum, overhead condenser, reboiler, and a feed/bottoms exchanger at the Alpine Central Facility. The primary purpose of the stabilizer and associated equipment is to optimize Alpine, Fiord CD3, Nanuq CD4 and any future WNS enhanced oil recovery projects. In addition, the stabilizer adds value and reserves by recovering and selling heavier condensate components that would otherwise be re -injected into the reservoir as part of the MI. Construction work was completed in December 2006 and the stabilizer was started up in late December 2006 with an initial production of 3 MBOPD. Emergency Power Upgrade Construction and tie-in has been completed to replace the original emergency power generators at Alpine. In 2000, dual Cummins Wartsilla diesel generators were placed in service at Alpine to provide emergency black start power. With plant power demands increasing in response to the upgrades described above, it became necessary to replace the diesel units with higher capacity turbine generator packages. On the 2004 ice road, dual Solar turbines were shipped over to Alpine. Construction commenced following the 2004 summer shutdown and turbines were placed in service in February 2005. The original power packages were removed from service in the spring of 2006. Conclusion Alpine reservoir performance remains strong. All Alpine wells planned for development of the main field have been drilled and completed as of November 2005. Limited additional drilling opportunities may be progressed in 2007 dependent upon results of the flow back of well CD4 -17 and of further sub surface study. Surface facility projects have continued to provide additional capacity to Alpine. The MWAG EOR project will continue throughout 2007 based on the excellent response seen to date. We foresee no significant obstacles to continued successful exploitation of the Alpine resource at this time. 7 If you have any questions or require additional information, please contact me at ConocoPhillips Alaska, Inc., P. O. Box 100360, Anchorage, Alaska, 99510-0360, Telephone: (907) 265-6822. Chris Wilson Supervisor, WNS Base cc: Tom Irwin, Director Alaska Department of Natural Resources Division of Oil & Gas 550 W. 7t" Avenue, Suite 8000 Anchorage, Alaska 99501-3560 Ms. Teresa Imm, Resource Development Manager Arctic Slope Regional Corporation 301 Arctic Slope Avenue, Suite 300 Anchorage, Alaska 99518-3035 Mr. Isaac Nukapigak, President Kuukpik Corporation PO Box 187 Nuiqsut, Alaska 99789-0187 Mr. Steve Dodds, Landman Anadarko Petroleum Corporation PO Box 1330 Houston, Texas 77251-1330 Attachment 1 - CRU Boundary as of August 15, 2005 Unit Boundary Tract Boundary APC,CPAI v Tract Number ° eAPC, CPN 6 /� `JIJ/1S.J Ic © 20 _X.213 I 22 0 4 8 SCALE IN MILES E 3�. 29 28 APC CPAI L 27 , 26 1® 33 7 3 3< ® :MVA , -3' 32 �I ff 3a 35 36 APC CPAI APC. `PPS APC, CPAI CPAI qvC; CPN 6 5 APC. CVN 4 3 2 C 6 5 17 I 3 2 ® -- —_._._ I_ _ AD13881� _ `% 16 i sees Ap13 W92 ] s v ,0 11 77 2 ] 1 L 10 10 88 69 ®glpC CPN 1 --.—_-- �— _.___�_ ADL338165 m3 Ws3 L390344 c c rc9 _ Ao a°s ^oL87]210a AD 2103 L3P 3 C. .CPAI'] APC. AP C 4 rx CPAI t4 ® IS Imo' +e n 8 � L _ 14 � �O 19 20 22 w ^ 16ALI- Cp. ^�^I 77 22 �ADL3�210] 025528 ADLt�?5535 gDl3)232106 APC,CPA aL ® 2e APC,ICPA1 ze ®v ^ N v 32 APC, C^AI APC CP ._� 28 1> 0 2P 78 ® ® -- — MC, CPN 3J 35 % 31 32 ASPC. I i .--- Ap;_36]212 A AD�B0098 ADL°Q5558 A➢10 655] AOL372109 AO1364214 PN APC CPN APG. CPN QD APC; CPN VCC,{CIAI APC, PN® ' 7 6 3 53 51 1 68 'S2 ] 9 eo 48 Ap3500]5 A 55588 ADL�]2095 AD 556° AAL, CPN APC. CPN [ N APC CPN ,CF I 56 ADl3som nouna9i ADu12oe6 Colville River '° _ ® APC, ® PA ® �� A°C CPN O ®' Unit Boundary - 82 - A. 76 79 aP[. CPN (�p11/l ® Nc tpN APC � CPA I AOLi64a9 ADL364211 ADU9o°6t i APC CPAI 31 32/ 120 2 A ,CPN 1 ® ASRCN 126 ADL38B903 A�j��y��/ AFC, CPN APC.PN 6 � ®11' 129 0 4 8 SCALE IN MILES E Attachmen+ ') - All Wells Drilled as of February " 2007 Surface Well Information Well Name Well Service 7" Csg Shoe Start of Completion End of Completion X start Y start TD X end Y end CD1-01 Injector 7752 386226 5977656 10289 384975 5979854 CD1-02 Injector 8201 388914 5978054 12773 386773 5982084 CD1-03 Injector 7816 387016 5975903 10897 388337 5973122 CD1-04 Producer 9444 390285 5979213 13977 392388 5975199 CD1-05 Injector 10633 392065 5979111 14515 393810 5975646 CD1-06 Injector 13500 395921 5978194 16024 397043 5975933 CD1-07 Injector 13477 395838 5971680 17542 397737 5968095 CD1-08 Producer 12515 394559 5970944 15837 396092 5967999 CD1-09 Producer 11894 393604 5979402 15350 395153 5976315 CD1-10 Producer 7909 387919 5977328 11693 389639 5973962 CD1-11 Injector 12293 393432 5969790 15057 394737 5967356 CD1-12 Producer 11656 392008 5969456 12912 392582 5968340 CD1-13 Injector 8841 389949 5976723 11300 391036 5974524 CD1-14 Injector 14073 397423 5974752 18939 399752 5970483 CD1-16 Injector 9595 391456 5973711 12600 392819 5971035 CD1-17 Producer 13181 395639 5975431 18590 398233 5970693 CD1-18 Producer 11382 389206 5968235 15056 390928 5964996 CD1-20 Injector 10634 389768 5969450 16114 392499 5964709 CD1-21 Injector 9049 381896 5979206 11087 380972 5981020 CD1-22 Producer 8430 387229 5978470 9236 386794 5979148 CD1-23 Injector 11473 394161 5974990 14477 395504 5972306 CD1-24 Producer 10771 392946 5974121 13706 394333 5971538 CD1-25 Producer 8887 390067 5973033 12147 391614 5970167 CD1-26 Injector 8554 388729 5972343 11134 389929 5970059 CD1-27 Producer 8500 387434 5971694 11492 388770 5969018 CD1-28 Producer 7449 385822 5974801 10468 387229 5972131 CD1-30 Producer 9520 380597 5978488 12850 379073 5981447 CD1-31 Injector 10388 379306 5977679 14364 377530 5981235 CD1-32 Producer 11128 378022 5977019 14353 376466 5979841 CD1-33 Injector 7878 384485 5974129 10854 385846 5971484 CD1-34 Producer 8410 383109 5973412 11190 384448 5970977 CD1-35 Producer 8158 384636 5977159 13450 382165 5981835 CD1-36 Injector 7654 383597 5975923 10654 382248 5978601 CD1-37 Injector 9095 386283 5970682 12134 387689 5967992 CD1-38 Producer 9170 384724 5970395 12240 386139 5967673 CD1-39 Injector 10288 383468 5969466 13298 384825 5966783 CD1-40 Producer 12042 382637 5967963 15438 384188 5964948 CD1-41 Producer 8333 382239 5975220 11170 380948 5977745 CD1-42 Injector 9054 380961 5974612 11608 379729 5976849 CD1-43 Producer 10065 380436 5972089 12921 381823 5969594 CD1-44 Producer 10070 379572 5973840 12811 378333 5976283 CD1-45 Injector 9032 381802 5972762 11950 383139 5970169 CD1-46 Injector 11334 387838 5967599 15187 389598 5964174 CD2 -01 Producer 12953 378098 5982112 17513 376080 5986195 CD2 -02 Injector 16048 359979 5982023 21178 357334 5986377 CD2 -03 Producer 13774 367095 5984985 15682 366191 5986658 CD2 -05 Producer 13712 363517 5970008 17816 361616 5973641 CD2 -06 Injector 9672 371098 5980645 16680 367816 5986833 CD2 -07 Injector 10857 373650 5982084 14977 371786 5985755 CD2 -08 Injector 12242 377278 5981611 18050 374565 5986743 10 Surface Well Name Well Service t.. Csg Shoe Well Information Start of Completion End X start Y start TD ... Completion X end Y end CD2 -09 Producer 12617 365177 5982158 16094 363562 5985233 CD2 -10 Producer 10702 372139 5982079 14475 370284 5985362 CD2 -11 Injector 13809 363590 5981961 18187 361600 5985857 CD2 -12 Injector 8677 368888 5978304 13632 366637 5982712 CD2 -13 Producer 10595 376177 5980472 14575 374339 5983995 CD2 -14 Producer 7671 371963 5975571 11056 370410 5978577 CD2 -15 Injector 9830 366147 5977039 14161 364157 5980881 CD2 -16 Injector 9529 375990 5977319 12500 374782 5980013 CD2 -17A Injector 8184 373143 5976621 11819 371497 5979862 CD2 -18 Injector 12112 362855 5975882 18019 360209 5981156 CD2 -19 Producer 8769 375572 5975101 11714 376896 5972473 CD2 -20 Producer 9163 369916 5979552 14570 367451 5984361 CD2 -22 Injector 7845 370575 5975090 11134 369051 5978002 CD2 -23 Producer 9676 367151 5978350 13438 365445 5981699 CD2 -24 Producer 10811 364768 5976380 14301 363212 5979501 CD2 -25 Producer 8722 369286 5974237 11994 367790 5977144 CD2 -26 Injector 8619 374207 5974408 11238 375406 5972081 CD2 -27 Injector 12461 377930 5967068 18250 380637 5961965 CD2 -28 Producer 8695 374897 5976522 13200 372799 5980502 CD2 -29 Injector 9556 376873 5975841 12560 378234 5973167 CD2 -30 Injector 11481 365217 5971303 15700 363306 5975062 CD2 -31 Producer 13598 361069 5974966 18131 358947 5978966 CD2 -32 Injector 8723 367954 5973557 11720 366579 5976218 CD2 -33B Producer 9982 366697 5972759 13078 365223 5975475 CD2 -34 Producer 7802 372917 5973731 8755 373367 5972891 CD2 -35A Injector 9063 375633 5971746 13500 377673 5967818 CD2 -36 Injector 13523 372731 5964073 17663 374634 5960399 CD2 -37 Producer 14162 371725 5963095 17085 373038 5960491 CD2 -38 Injector 9209 373424 5969394 13010 375164 5966020 CD2 -39 Producer 9122 374692 5970192 12651 376369 5967087 CD2 -40 Injector 11208 365775 5970211 14250 367117 5967484 CD2 -41 Producer 9532 372019 5968832 13024 373637 5965742 CD2 -42 Producer 9633 367542 5970978 13138 369171 5967884 CD2 -43 Producer 13106 364417 5968231 19040 367196 5962998 CD2 -44 Injector 11319 378889 5972087 14555 380338 5969198 CD2 -45 Producer 9972 377360 5971508 13402 378989 5968491 CD2 -46 Injector 7879 371539 5973093 11000 372970 5970320 CD2 -47 Producer 10840 369515 5967325 14580 371256 5964017 CD2 -48 Injector 10074 370711 5968227 13622 372304 5965058 CD2 -49 Injector 8890 368809 5971733 11874 370200 5969094 CD2 -50 Producer 7909 370191 5972556 11624 371794 5969207 CD2 -51 Injector 13246 380577 5968583 17320 382471 5964985 CD2 -52 Producer 12897 379292 5967820 16881 381127 5964289 CD2 -53 Producer 12394 376772 5966066 16985 378960 5962036 CD2 -54 Injector 14378 361169 5970560 18250 359460 5974033 CD2 -55 Injector 12210 367573 5966569 15238 368976 5963888 CD2 -56 Injector 14391 362859 5967271 19554 365279 5962714 CD2 -57 Injector 12642 375598 5965124 16433 377321 5961749 CD2 -58 Producer 12129 373883 5965245 16389 375838 5961468 CD2 -59 Injector 15743 358798 5974508 20027 357078 5978426 11 Surface Well Name Well Information Well Csg Service Shoe Start of Completion End v, Completion X start Y start TD X end Y end CD2 -60 Injector 14331 369427 5962859 18695 371542 5959079 CD4 -17 Injector 13334 1508042 5957009 17975 1505966 5961150 12 Attachment 3 - MWAG conversion status at CD1 Alpine MWAG Status - CD1 CD 1.05 1 st CV cle I 2nd C cle I 3rd Cy cle 4th C cle 5th Cy cle I 6th Cy cle 7th Cy cle 8th Cy cle 9tl Well Conversion Date HCPV Injected Conversion Date HCPV Injected Conversion Date HCPV Injected Conversion Date HCPV Injected Conversion Date HCPV Injected Conversion Date HCPV Injected Conversion Date HCPV Injected Conversion Date HCPV Injected Convey. Date CD -1-01 1/25/2001 5.8% 10/19/2.001 4.3% 4/4/2002 7.1 % 7/20/2003 6.4% 6/1112004 5.6% 2/13/2005 4.4% 9/2/2005 8.1% 7/2/2006 2.4% CD1-02 2/7/2001 9.8% 12/21/2001 11.1% 7/19/2002 9.9% 10/30/2003 5.9% 7/3/2004 3.8% 11123/2004 5.4% 6/3/2005 10.2% 4124/2006 4.3% CD1-03 1 4/10/2001 14.8% 1 6/5/2002 16.3% 7/19/2003 7.0% 12/19/2003 4.6% 4/29/2004 6.3% 11/23/2004 6.6% 6/2/2005 8.5% 12/15/2005 4.7% 12i CD 1.05 1/1/2001 49.31 6/23/2002 1 59.9% CD1-06 12/13/2000 196.1 CD1-07 7/13/2004 19.3% 4)11/2005 15.1 % 11 CD1-11 1/26/2005 16.5% 8127/2005 11.1 % 12 CD1-13 1/25/2001 10.4% 11/22/2001 17.1% 11 CD1-14 9/4/2001 160.6% 4/26/2005 90.7% CD1-16 318/2001 13.7% 11116/2002 12.6% 7 CD1-20 1/23/2005 14.7% 1/14/2006 1 9.3% 8.5% 4/2/2006 1 8.6% 1_8/29_/2006 1 11.7% 7.8% 3/31/2006 1 10.1% 1 9/3/2006 7.7% 12.2% 10/30/2003 4.7% 6/1212004 5.6% 5.4% 6/3/2005 1 6.6% 1 4/11/2006 7.4% CD1-21 3/10/2001 12.3% 111/7/2001 22.3% 1 7!19/2003 4.1 % 11211712003 4.1 % 6/12/2004 1 4.6% 6/3/2005 1 3.5% 1 12!14/2005 1 7.6% CD1-23 3/30/2001 18.8% 4/3/2002 28.5% 7120/2003 15.0% 10/3/2004 6.7% 4/12/2005 26.6% CD1-26 1/25/2001 18.8% 7/26/2002 14.2% 9/19/2003 14.0% 1/16/2005 6.5% 10/5/2005 6.0% 3/29!2006 7.3% CD1-31 12/13/2000 18.0% 10/6/2001 22.6% 10/21!2003 2.8% 4/29/2004 5.6% 2/13/2005 8.0% 3/29/2006 5.0% 1 12/9/2006 0.3% CD1-33 2118/2001 12.6'x, 11/29/2002 10.8% 7!5/2004 4.4% 6/24/2005 8.3% 12/9/2006 0.31/. CD1-36 1125/2001 17.8% 7/19/2003 12.5% 1/16/2005 4.6% 1/13/2006 5.8% CD 1.37 2/20/2001 20.2% 6/23/2002 13.8% 7/21/2003 8.2% 1/16/2005 8.0% CD 1.39 1/25/2001 22.4% 6/25/2003 21.1 % 9/19/2003 10.1 % 10/31/2004 9.1 % 12/4/2005 9.7% CD1 -42 1/25/2001 1 12.0% 2/28/2002 20.0% 9119/2003 7.07/. 10/31/2004 3.2% 7!812005 8.8% 9/27/2006 1.3% CD -1-45 212/2001 1 15.6% 2/1QLZ� _ 716/2004 5.5 6/7/2005 7.8% 12!1812006 0.2% CD1-46 1 8/28/20041 18.5% 11 Nomenclature: SW Sea water injection MI Miscible gas injection Dr Gas Dry gas injection 13 8/311/2006 1 2.0% Attacnment 4 - MWAG maturity (;Dl CD1-01 �7 CD1-02 C D 1-03 C D 1-05 CD1-06 C D 1-07 CD1-11 CD1-13 CD1-14 CD1-16 C D 1-20 CD1-21 C D 1-23 CD1-26 CD1-31 C D 1-33 CD 1-36 C D 1-37 C D 1-39 C D 1-42 C D 1-45 CD1-46 C D1 MWAG Status 700 r/o 7"o r?o 770 r, r r"o /,5o ' 'o o o o o `'fix '�o o ^ `Poo Cum HCPVI {°o) 14 Attachment 5 - MWAG conversion status at CD2 Alpine MWAG Status - CD2 1 st Cycle 2nd Cycle 3rd C cIe 4th Cycle 5th C cIe 6t Well Conversion Date HCPV Injected Conversion Date HCPV Injected Conversion Date HCPV Injected Conversion Date HCPV Injected Conversion Date HCPV Injected Convert Date CD2 -02 12130/2005 23.50 12/4/2006 1.2% CD2 -06 11/10/2003 19.2% 10/30/2004 11.0% 6/23/2005 13.41 3/20/2006 1 10.3% 110/31/2006F2.9`/` CD2 -07 2/6/2004 23.8% 2/11/2005 12.1% 8/2512005 10.6% 111/19/20051 10.6% 3/17/2006 1 1H% 812712[ CD2 -08 CD2 -11 3/25/2003 2/9/2006 13.4% 16.0% 3/28/2004 5/27/2006 13.5% 1 1&7% 2/1212005 12/5/2006 13.3% 3.0 % 3124/2006 1 9.8% CD2 -12 6125/2003 24.6 % 10/3/2004 13.8% 6/22/2005 4.6% 12/8/2005 10.5% 6128/2006 8.0% CD2 -15 2/24/2002 11.7% 8/612003 14.5% 4/9/2005 5,9% 1/11/2006 1.8% 4/22/2006 5.0% CD2 -16 9/25/2002 9.2% 12/19/2003 9.8% 2/15/2005 4.9% 8/27/2005 5.2% 3/2112006 5.7% CD2 -17 CD2 -18 3/5/2002 10/3012003 11.1% 14.8% 10/30/2003 9/3/2006 6.9% 2.0% 10/30/2004 8.9% 4/24/2006 4.4% CD2 -22 6/812002 13.5% 9/22/2003 15.1% 218/2005 6.1 % 8/27/2005 1 7.8% 12/27/2006 9.0% CD2 -26 CD2 -27 2/22/2002 1/8/2004 15.0% 15.0% 7/23/2003 5/24/2006 14.8% 3.4% 4/9/2005 1 5.7% 12/12/2005 7.8% CD2 -29 10/30/2002 8.91/. 10/10/2003 13.4% 1 211412005 5.7% 9/3/2005 1 5.5% 2/14/2006 1 9.7% 11212612 CD2 -30 2/3/2004 13.8% CD2 -32 3/31/2002 12.7% 9/23/2003 9.6% 7/7/2005 9.4% CD2 -35 4/26/2003 12.2% 4/29/2005 7.9% 5/20/2006 4.2 % CD2 -36 4/28/2003 16.5% 6/4/2005 10.3% 4/2612006 5.7% CD2 -38 10/17/2002 12.3% 4/29/2005 8.6% 9/24/2006 1.3% CD2 -40 9/20/2003 11.3% CD2 -44 10/22/2002 14.3% 19/21/2003 11.3% 7/9/2004 10.2% 211512005 1 9.5% 110/25/20051 9.7% 1 7/2/2006 5.2% CD2 -46 5/30/2002 10.7 % 6/10/2004 6.6% 717!2005 10.0 % 12/1312006 0.2% CD2 -48 7119/2002 9.3% 10/2/2004 9.0% 1013012006 0.7% CD2 -49 2122/2002 4.0% 10111/2002 4.0% 4/17/2003 1.6% 10/22/2003 i.6% 1 6/4/2005 1 4.6% 12/23/2006 5.7 CD2 -51 714/2003 16.6% 12/5/2005 7.5% CD 2.54 11/24/2004 20.4% 3/27/2006 2.7% 10/17/2006 1.8% 11/2/2006 CD 2-59 Nomenclature: SW Sea water injection Ml Miscible gas injection Dr Gas Dry gas injection 15 Ah Cycle I 8th Cycle I 9th C cle ,iversion HCIN Conversion HCPV Conversion Date Injected Date Injected Date Ilni Attachment 6 - MWAG maturitv at CD2 CD2 MWAG Status CD2 -02 CD2 -06 CD2 -07 CD2 -08 CD2 -11 CD2 -12 CD2 -16 CD2 -16 CD2 -17 CD2 -18 CD2 -22 CD2 -26 CD2 -27 CD2 -29 CD2 -30 CD2 -32 CD2 -35 CD2 -36 CD2 -38 CD2 -40 CD2 -44 CD2 -46 CD2 -48 CD2 -49 CD2 -51 CD2 -54 CD2 -55 CD2 -56 CD2 57 CD2 59 CD2 -60 0 10 20 30 40 60 60 70 80 90 100 Linn HCPVI (%) 16 Attachment i loo -- go - 80 009080 CL 70 0 O 60 - 0 O 50 O 40- 0 0-p 30 20 -- lo-- 0 -100 0 0 17 Attachment 8 - Alpine Development: drilled and planned wells Wells drilled in 2006 are indicated as red lines. Wells drilled prior to 2006 are indicated as thin dark green (producers) and thin dark blue (injectors) lines. IN 11 -9000 Feet